2015 09 Power Engineering

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YEARS
119
THE 316(B) RULE
ONE YEAR LATER
SMALL GAS TURBINES
ONE OF THE BIGGEST TRENDS IN DISTRIBUTED GENERATION
EMISSIONS CONTROL
MULTI-POLLUTANT COMPLIANCE OPTIONS
SPECIAL REPORT:
BIG Solar
September 2015 • www.power-eng.com

For info. http://powereng.hotims.com RS#1

CHIEF EDITOR — Russell Ray
(918) 832-9368 russellr@pennwell.com
ASSOCIATE EDITOR — Sharryn Dotson
(918) 832-9339 sharrynd@pennwell.com
ASSOCIATE EDITOR — Tim Miser
(918) 831-9492 tmiser@pennwell.com
CONTRIBUTING EDITOR—Brad Buecker
CONTRIBUTING EDITOR—Brian Schimmoller
CONTRIBUTING EDITOR—Robynn Andracsek
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(918) 832-9378 deannat@pennwell.com
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DEPARTMENTS
2 Opinion
4 Industry News
8 Gas Generation
10 View on Renewables
11 Energy Matters
46 What Works
48 Products and Literature
56 Ad Index
18 Circulating Fluidized Bed
Scrubber vs. Spray Dryer Absorber
In response to more stringent air emissions regulations,utilities are under
pressure to add flue gas desulfurization to their coal-fired units.Power Engineering
investigates the differences between state-of-the-art circulating fluidized bed
scrubbers and the latest advanced spray dryer absorber designs.
34 316(b): One Year Later
As the one-year anniversary of the EPA’s newest 316(b) regulations approaches,
Power Engineering examines the details of the rule and how power producers can
best meet the revised mandates.
42 Maintaining Maximum Efficiency
in Power Generation Units
Pressure to lower industrial carbon dioxide emissions continues to foster increased
interest in improved efficiency at steam generating facilities.Read about some of
the issues operators face in their quest for more efficient plants.
24 Improving the Flexibility and Efficiency of
a Gas Turbine-Based Distributed Power Plant
By building smaller,more flexible gas-fired power plants closer to actual load
centers,network operators can better satisfy their customers’power demands.
Learn how an efficient and flexible distributed generation model can help power
producers meet the challenges of today’s power landscape.
38 Turbine Oils: A Key Factor in System Reliability
Turbine lubricants must perform under the hostile conditions of heat,friction,and
chemical degradation.Learn how the right mix of oil and additives,combined with
a disciplined program of testing and maintenance,can prevent unwanted varnish
and forestall premature equipment wear.
12 Large-Scale
Solar on the Rise
The cost of generating electricity from utility-scale solar power has
plummeted in recent years,but the possible end of federal investment
tax credits threatens to temper an otherwise sunny outlook for the
industry.Find out what the future holds for solar in NorthAmerica.
No.9,September 2015

2
OPINION
www.power-eng.com
In another bizarre twist, the CO2
lim-
it for existing plants is 1,307 pounds
per megawatt-hour while the CO2
lim-
it for new plants is 1,400 pounds per
MWh. Under the final rule, the stan-
dard for an existing plant is more strin-
gent than the standard for a brand new
plant. What gives?
The new standards can’t be achieved
without installing a carbon capture
and storage system, an expensive and
questionable technology.
“We just commissioned the most
efficient coal-fired power plant in the
country in Arkansas and its CO2
emis-
sions are just under 1,800 pounds
per megawatt-hour,” said Mark Mc-
Cullough, executive vice president of
Generation at American Electric Power.
The new CO2
standards are among a
host of new, costly requirements faced
by coal-fired power plants. The new
rules mean as much as 90,000 MW of
coal-fired generation will be retired be-
tween now and 2040. Most of those re-
tirements are expected to be achieved
by 2020.
The only real option for replacing
that dispatchable output is power fu-
eled with natural gas. “The risk profile
of coal and nuclear, from a utility per-
spective, is just too high,” McCullough
said. But too much reliance on natural
gas could lead to serious economic and
security issues for the nation’s power
sector, McCullough said.
“Absence of diversity is a recipe for a
big problem,” he said.
If you have a question or a comment,
contact me at russellr@pennwell.com.
Follow me on Twitter @RussellRay1.
T
he minute the Obama admin-
istration unveiled its final plan
to cut greenhouse gas emis-
sions from U.S. power plants, oppo-
nents launched the first of many legal
efforts to kill what some have described
as the most prejudicial regulation ever
proposed by the U.S. Environmental
Protection Agency (EPA).
The Clean Power Plan calls for sweep-
ing new requirements to cut carbon di-
oxide (CO2
) emissions 32 percent below
2005 levels by 2030. The rule will require
a massive restructuring of the power
sector. It will decimate coal by establish-
ing unattainable CO2
standards for coal
plants. It does nothing to promote the use
of cleaner-burning natural gas, but it will
stimulate the deployment of intermittent
wind and solar power with new incen-
tives. What’s more, it will require states to
spend billions to comply with a rule that
may ultimately be vacated by the U.S. Su-
preme Court.
Several states have asked a federal ap-
peals court to stay the controversial plan
until the courts decide whether the EPA
has the authority to force states to limit
CO2
from U.S. power plants. More states
are expected to join a lawsuit challeng-
ing the rule, a case that will likely end
years from now at the Supreme Court.
What are the plaintiffs’ chances of
winning the case against the EPA? Bet-
ter than average, I would say.
On June 29, the high court struck
down the EPA’s Mercury and Air Toxics
Standard, better known as the MATS
rule, which established the first limits
on mercury, arsenic and acid-gas emis-
sions from coal-fired power plants.
The final MATS rule was issued back
in 2012 and became effective earlier
this year. However, the Supreme Court
remanded the rule to the D.C. Circuit
Court, saying the EPA failed to consid-
er the $9.6 billion cost of implement-
ing the new rule when drafting it. The
industry spent billions to comply with
the MATS rule, which now faces the
possibility of being vacated.
How the Supreme Court will rule on
the Clean Power Plan is anyone’s guess,
but its ruling on the MATS rule is com-
pelling evidence the high court may
reject the plan.
The states’ case against the Clean
Power Plan centers on the EPA’s au-
thority to regulate greenhouse gas
emissions from power plants under
section 111(d) of the Clean Air Act
(CAA). The states contend power plant
emissions are already regulated under
section 112 of the CAA. The CAA pro-
hibits the EPA from regulating power
plant emissions under more than one
section of the law.
What’s more, opponents of the plan
argue the EPA is already regulating pow-
er plant emissions under the MATS rule
and, thus, does not have the authority
to regulate such emissions under section
111(d) of the CAA. However, if the MATS
rule is vacated by the D.C. Circuit Court,
that legal argument will vanish.
“That may undermine one of the
key legal challenges to the EPA’s Clean
Power Plan,” said Andy Byers, associate
vice president at Black & Veatch. “A lot
of folks are speculating the EPA may go
back to the circuit court and ask them
to overturn their (MATS) rule.”
What You Need to
Know About the Clean
Power PlanBY RUSSELL RAY, CHIEF EDITOR

Indeck Group of Companies
Indeck Keystone Energy LLC • Indeck Power Equipment Co. • Indeck Boiler Corp. • Indeck Energy Services Inc.
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4
INDUSTRY NEWS
www.power-eng.com
PJM Increases Payments to
Power Producers 37 Percent
PJM Interconnection, the largest
electric grid in the U.S., will increase
payments to power generators 37 per-
cent.
The company said the increase will
begin in June 2018, and will be $164.77
per megawatt (MW) per day, as deter-
mined in a capacity auction held last
month. The price is almost $45 above
the previous 12 months reached in an
auction last year.
Precipitating the increase was a deci-
sion by federal regulators to allow PJM
to penalize generators that fail to sup-
ply promised power. The decision was
intended to prevent unplanned shut-
downs and fuel shortages, like those
that greatly inflated prices during the
winter of 2014.
Capacity costs were set at higher lev-
els for two regions because of supply
constraints. The eastern mid-Atantic
region, including New Jersey, Delaware
and Pennsylvania, finalized a price of
$225.42/MW/day, while prices in Ex-
elon Corp.’s ComEd utility territory
rose to $215.Under the new rules, the
grid operator can impose penalties of
about $2,800 per megawatt-hour on
generators who fail to deliver promised
power during emergency hours.
Exelon-Pepco Merger in Doubt
After Regulators Reject Proposal
The D.C. Public Service Commis-
sion last month rebuffed a multi-bil-
lion dollar proposed merger between
power companies Exelon and Pepco.
The three-member commission unani-
mously rejected the $6.8 billion merger.
Chicago-based Exelon announced in
April 2014 plans to acquire Washing-
ton-based Pepco Holdings. The deal
would have created the largest electric
and gas utility in the region with about
10 million customers in cities includ-
ing Baltimore, Chicago, Philadelphia
and Washington.
Despite garnering the approval
of several surrounding states, Exelon
and Pepco failed to reach settlements
with regulators in Washington D.C.
Chairwoman Betty Ann Kane said
in a statement the companies failed to
show the merger was a benefit to the
public.
“The evidence in the record is that
sale and change in control proposed in
the merger would move us in the oppo-
site direction,” Kane said.
The companies expressed disap-
pointment in the decision and said the
commission did not recognize the ben-
efits of the merger.
Excel Energy Cuts GHG
Emissions 20 Percent
Xcel Energy has become the first utility
in the nation to register nearly a decade’s
worth of greenhouse gas emissions data
with The Climate Registry, a nonprofit
organization that operates voluntary
and compliance greenhouse gas report-
ing programs throughout the world.
The company pledged to begin re-
ducing emissions in 2005, according to
Xcel Energy Vice President Frank Prag-
er. In the years since, the utility has
seen more than a 20-percent reduction
in carbon dioxide emissions and is on
track to achieve a 30-percent reduction
companywide by 2020.
Xcel Energy reached Climate Regis-
tered status by measuring and report-
ing the company’s emissions from
2005 to 2011. The data was then ver-
ified by a third party.
The company’s emissions from 2012
to 2014 are being verified and regis-
tered with The Climate Registry.
Obama Announces $1 Billion
in DOE Initiatives
President Obama last month an-
nounced more than $1 billion in initia-
tives promoting clean energy.
The president’s Clean Power Plan per-
mits the Department of Energy’s Loan
Programs Office to guarantee up to $1
billion for commercial-scale distributed
energy projects like rooftop solar, smart
grid technology and methane capture for
oil and gas wells.
Distributed energy technologies reduce
greenhouse gas emissions while strength-
ening energy security and creating eco-
nomic opportunity, but projects often
encounter roadblocks when it comes to
lenders who are unwilling to take on the
risk of a new technology.
Additionally, the DOE is awarding
$24 million through the Advanced Re-
search Projects Agency – Energy for 11
high-performance solar power projects
aimed at lowering the cost and improv-
ing the performance of solar photovol-
taic power systems.
GE Signs its Largest Battery
Storage Deal to Date
GE announced it will provide Coachel-
la Energy Storage Partners (CESP) with a
30-MW battery energy storage system as
part of CESP’s supply contract with the
Imperial Irrigation District (IID).
Representing GE’s largest energy stor-
age project to date, the plant will be built
in California’s Imperial Valley, 100 miles
east of San Diego. The facility will aid grid
flexibility and increase reliability on the
IID network by providing solar ramping,
frequency regulation, power balancing,
and black start capability for an adjacent
gas turbine.
GE will provide CESP with an integrat-
ed energy storage solution, configured

6 www.power-eng.com
using GE’s Mark VI plant controls, GE
Brilliance MW inverters, GE Prolec trans-
formers, medium-voltage switchgear, and
advanced lithium ion batteries housed in
a GE purpose-built enclosure. The plant
will be operated by ZGlobal, an engineer-
ing collaborator with CESP, for the first 18
months, after which control will transfer
to the IID. Construction is expected to
begin early next year, with commercial
operation scheduled for the third quarter
of 2016.
NRC Issues Corrective Actions
Against Millstone 2 Nuclear Unit
Dominion is implementing a range
of corrective actions at the Millstone
Unit 2 nuclear plant in Connecticut to
address violations.
In September 2011, the NRC became
aware that Dominion had submitted re-
quests for approval of amendments to
the Millstone 2 operating license that
were incomplete and inaccurate. The
requests were to modify requirements
for Unit 2’s charging pumps and irra-
diated fuel decay time. NRC’s Office of
Investigations began an investigation
the following November to determine
if there was any wrongdoing. On April
29, 2015, NRC notified Dominion that
the violations were considered for esca-
lated enforcement.
The first violation was for a will-
ful violation for changes made to the
plant’s Updated Final Safety Analysis
Report, without a license amendment,
that removed credit for a specific type
of safety-related pump in the mitiga-
tion of a plant accident. The second vi-
olation was a non-willful violation for
a failure to provide complete and accu-
rate information to the NRC pertain-
ing to the changes. The third violation,
related to the utility’s failure to obtain
a license amendment prior to making
changes related to spent fuel pool heat-
load analysis, was not considered for
escalated enforcement.
Louisiana Regulators Approve
Merger of Entergy Utilities
The Louisiana Public Service Commis-
sion approved the merger of Entergy Lou-
isiana LLC and Entergy Gulf States Louisi-
ana LLC into a single utility.
The new utility will operate under the
name Entergy Louisiana LLC after the
deal closes Oct. 1. It will have over $16.5
billion in assets and 66,194 GWh in com-
bined sales. Louisiana’s utilities provide
electricity to more than one million cus-
tomers, and natural gas service to over
93,000 customers in the greater Baton
Rouge area. The merged company will be
a unit of Entergy Corp.
GE’s Gas Turbine Surpasses
75 Million Operating Hours
GE’s LM2500 aeroderivative gas tur-
bine has reached a milestone of 75 mil-
lion combined operating hours.
The current fleet of gas turbines totals
more than 2,800 turbines across six con-
tinents. Main features includes reaching
full power within 10 minutes, direct drive
for 50-hertz and 60-herts power genera-
tion, variable speed for mechanical drive,
dual-fuel capability for distillate or natu-
ral gas, reduced NOx with dry low emis-
sions combustor and natural gas fuel and
optional steam or water injection system
for NOx control.
The first LM2500 gas turbine began op-
erating on a U.S. Navy cargo ship, GE said
in a release. The turbine consists of a 16 or
17-stage axial flow compressor, annular
combustor, two-stage, high-pressure, sin-
gle rotor gas turbine and efficient six-stage
power turbine.
DOE Picks 8 Projects to Receive
Funding for Cutting Cost of CO2
Capture and Compression
The U.S. Department of Energy’s
(DOE) National Energy Technology
Laboratory has selected eight projects to
receive funding to construct small- and
large-scale pilots for reducing the cost of
carbon dioxide (CO2) capture and com-
pression through DOE’s Carbon Capture
Program.
The Carbon Capture Program is de-
veloping technologies that will enable
cost-effective implementation of carbon
capture and storage (CCS) in the pow-
er generation sector and ensure that the
U.S. will continue to have access to safe,
reliable and affordable energy from fossil
fuels. The program consists of two core
research technology areas, post-combus-
tion capture and pre-combustion capture,
and also supports related CO2 compres-
sion efforts. Current research and devel-
opment efforts are advancing technol-
ogies that could provide step-change
reductions in both cost and energy pen-
alty compared to currently available tech-
nologies.
MidAmerican Building Iowa
Wind Farms for $900 Million
MidAmerican Energy says it will build
its next two wind farms in northwest
Iowa.
The company says there will be 134
generators at the Ida County site and 104
at the site in O’Brien County, providing
a combined capacity of 552 megawatts.
The estimated investment for the two
projects is $900 million. A MidAmeri-
can vice president, Mike Gehringer, says
that by the end of the year, more of Mi-
dAmerican’s electricity will come from
wind than from any other single source.
MidAmerican spokeswoman Ruth Com-
er says that by the end of 2016, when both
projects are completed, the Berkshire Ha-
thaway-owned company will have more
than 2,000 wind turbines across Iowa.

NOx Reduction Catalyst
Bring down NOx and
mercury emissions
Regulators worldwide are clamping down on mercury emissions, and complying with the
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series NOx reduction catalysts
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8
GAS GENERATION
www.power-eng.com
complete borescope inspections at recom-
mended intervals. Although not a precise
indicator of part condition, signs of major
damage such as large crack indications,
excessive wear or oxidation, foreign object
damage, tip rubbing, and missing coating
should be explored. It is important to
document damage that occurs over time
in order to track the progression of known
conditions.
During major overhauls, users should
conduct cycling-targeted, non-destructive
testing (NDT), particularly on rotating
hardware. Depending on material, there
are multiple NDT techniques that can
identify cracks. These include liquid pen-
etrant, magnetic particle, and eddy cur-
rent inspections. Users should complete
pre- and post-repair inspections, especial-
ly if weld repair is required. In addition,
they should inspect the integrity of the
coating and determine if new coatings are
required. Always review repair inspection
reports for non-conformances so as to un-
derstand the condition of hardware prior
to reuse.
ASSESSMENT
FOR PART REUSE
With inspection results in hand, it must
then be determined if it is safe to continue
to use hardware. Recall the difference in
failure modes between base loaded and
cycling machines and the fact that many
parts are life limited by time at tempera-
ture failure modes. When coupled with
the results of the cycling targeted failure
mode inspections, knowledge of the ac-
cumulated operating hours of hardware
enables educated decisions concerning
part reuse. Given the cost of replacement
hardware, significant monetary benefits
can be realized using this strategy.
G
as turbine maintenance inter-
vals are determined by hours,
starts, or a combination of both.
The latter is often referred to as equivalent
operating hours (EOH). The increasing
integration of renewable energy sourc-
es into generation portfolios has meant
changes in dispatch, and many tradition-
ally base-loaded assets are being forced
to load follow and on-off cycle, as seen
in many gas turbine and combined-cycle
arrangements across the country. With
such shifts in operational patterns
comes a shift in the failure modes that
manifest, as well as the inspection
techniques required to effectively diag-
nose these respective modes. Given the
competitive marketplace, it is valuable
to understand applicable failure modes
and inspection techniques to effective-
ly balance the fine line between scrap-
ping parts prematurely and running
hardware beyond safe conditions.
CYCLING VS. BASE
LOAD FAILURE MODES
When a unit starts and stops, it is ex-
posed to significant cyclic stresses in ad-
dition to large thermal transients in the
high-temperature sections of the engine.
This can lead to thermal mechanical fa-
tigue or low-cycle fatigue cracking. After
cracks begin, they continue to propagate
with each new cycle. If not addressed in
time, liberation of a rotating blade can
lead to substantial forced outage time and
repair costs.
For cycling units, it is also common to
sustain damage at interface or contact sur-
faces. Damage occurs from the repetitive
relative movement between surfaces, or as
a result of increased deflection of the rotor
through critical speeds. Some examples
of these surfaces include rotor to blade
root interfaces, tip contact faces on adja-
cent shrouded blades, and compressor or
turbine blade tips. In addition, cycling has
been shown to increase coating spallation
rates for coated parts, thus leading to pre-
mature oxidation of the hardware. The
impact of cycling is not limited to a sin-
gle section of the gas turbine. TG Advisers
has been involved in root cause failure
analyses ultimately attributed to cycling
in the compressor, combustion, and hot
sections of gas turbines.
It is also important to understand base
load failure modes. Base loaded machines
are mainly limited by failure modes that
result from prolonged operation at ele-
vated temperatures. These failure modes
include creep, coating/surface oxidation
damage, and embrittlement. Creep dam-
age is very difficult to detect non-destruc-
tively. As a result, hot section rotating
blades often have conservative life guide-
lines. This design philosophy is under-
standable given the scatter in material
properties, difficulty of detecting creep,
and severity of a blade failure. The risk for
failure modes that require extended time
at high temperatures, such as creep, is less
in gas turbines that exhibit cycle dominat-
ed maintenance intervals.
CYCLING-TARGETED
INSPECTIONS
The key to effective inspections is un-
derstanding the applicable failure modes
and how they manifest. This holds true
for broad condition inspections such as
in-situ borescope inspections, as well as
for detailed inspections completed during
major outages.
Prior to overhaul, and as a routine
maintenance practice, users should
Renewable Energy – Pushing
Gas Turbine Components to
Their Cycling Limit!
BY THOMAS R. REID,TG ADVISERS, INC.

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VIEW ON RENEWABLES
www.power-eng.com
– sweeping a greater area to make the
most of the available wind resource.
At an average wind speed of 7.5 me-
ters per second (nearly 17 miles per
hour), the Siemens SWT-2.3-120 yields
an increase of nearly 10 percent in an-
nual energy production (AEP) com-
pared to that of its pioneering prede-
cessor under the same
conditions – helping
to deliver higher re-
turns and a decrease
in the Levelized Cost
of Energy .
Production of this
new wind turbine
will begin in 2017,
and we are pleased
that its production will support clean
energy jobs here in the U.S., where we
have close to 2,000 workers in our new
unit and service businesses.
The nacelles and hubs will be as-
sembled at our facility in Hutchinson,
Kansas, and the blades will be manu-
factured at our blade factory in Ft. Mad-
ison, Iowa. And our national network
of wind service technicians is ready to
keep these turbines running optimally
throughout their lifecycle.
With more than 5,000 wind turbines
installed in the U.S., Siemens is leading
the effort to ensure that wind power is
an increasingly important part of the
nation’s energy mix.
At Siemens, we have more than 30
years of global experience in onshore
wind – and this new turbine is the lat-
est example of our strong commitment
to the growth of wind energy in the
United States.
T
he Department of Energy’s
Wind Vision report recently laid
out a plan to double wind ener-
gy in the U.S. by 2020, double again to
20 percent by 2030, and expand to over
one third of energy production by 2050.
With policymakers in Washington
focusing on reducing greenhouse gas
emissions, wind power is a natural com-
plement to fast-growing natural gas – a
prime building block for lowering car-
bon emissions. The U.S. already leads
the world in the amount of electricity
that is produced by wind – with more
than 181 million megawatt hours in
2014 – and the cost of wind energy has
dropped by half over the past five years.
As a share of the nation’s energy mix,
wind has grown from under 1 percent to
nearly 5 percent over the past eight years
– competing with natural gas for the top
spot of new power added to the system.
Because it is a low-cost solution with
zero emissions, it is clear that wind ener-
gy will play an important role in cost-ef-
fectively meeting the goals set forth by
the Obama administration.
In order to continue to reduce the
cost of wind energy, ongoing technol-
ogy enhancements are essential. Be-
cause of performance enhancements,
onshore wind is nearly reaching grid
parity. At Siemens, we are committed
to continually enhancing our technol-
ogy in order to grow the wind indus-
try here in the U.S. Earlier this year,
at the 2015 AWEA WINDPOWER Con-
ference & Exhibition in Orlando, Sie-
mens announced the latest addition
to our G2 product platform. This new
SWT2.3-120 wind turbine builds upon
the proven design principles of our G2
platform. Nearly 8,000 units have been
installed globally.
With wind power becoming an
increasingly important part of the
U.S. energy mix, this new turbine
was designed in America specifically
to meet the needs of the American
market. The SWT-
2.3-120 offers proven
technology tailored
to local requirements
and designed to
lower the levelized
cost of energy.
Building upon the
achievements of the
SWT-2.3-108, the new
SWT-2.3-120 features a high-perfor-
mance 120-meter rotor that enables en-
hanced energy production, lower sound
power levels and improved operating
temperature and altitude capabilities.
At our aerodynamic R&D center in
Boulder, Colorado, the new blade type
was designed to optimize the perfor-
mance of next generation wind com-
ponents – resulting in an aero-elastic
blade design that improves efficiency
and reduces loads through intelligent
use of the blade’s flexing capabilities.
This allows for the SWT-2.3-120’s larg-
er rotor size without a proportional in-
crease in structural loading – decreas-
ing wear and tear on the turbine.
The new blade was designed with the
goal of increasing energy production
for sites with medium to low wind con-
ditions, which comprise a significant
part of the U.S. market. The 59-meter
blades extend the reach of the rotor
WIND POWER:
Made for
American NeedsBY JACOB ANDERSEN, CEO ONSHORE AMERICAS, SIEMENS WIND POWER & RENEWABLES DIVISION
“As a share of the
nation’s energy
mix, wind has
grown from under
1 percent to nearly
5 percent over the
past eight years.”

11
ENERGY MATTERS
www.power-eng.com
April EscamillaRobynn Andracsek
communities were the least likely
to mount a serious challenge to the
industry because low income people are
often less well-educated, have less access
to computers and internet technology,
are less knowledgeable of how to access
and interpret environmental data, and
are the least likely to have the resources
for a time consuming legal battle.”
The Freedom of Information Act
(FOIA), enacted in 1967, is the usual
method to obtain records about a
plant’s operation: emissions, limits, or
almost anything needed to demonstrate
compliance (other than business
confidential information). For larger,
more publically sensitive projects such
as those at power plants, many states
have already adopted a policy of creating
websites where the most requested
documents can be downloaded by the
public. This simple action saves the
agency manpower in fulfilling repetitive
FOIA requests. However, FOIA requests
and state websites put the burden of
transparency on the government and
not the regulated entity. By requiring
each coal plant to post their compliance
information on the internet, neighbors,
activists, and other interested parties
can play armchair watchdog.
For now, EPA seems to have met the
needs of all parties involved. Citizens
can scrutinize their local utility, state
agencies can redirect their budgets to
enforcing other regulations, and EPA
can stay neutral until they are dragged
into action by a lawsuit. And the
utilities? While they are busy managing
ash and protecting the environment,
citizen groups will be watching every
move.
T
he new rules on Coal Com-
bustion Residuals (CCR) have
a novel requirement aimed at
making compliance efforts transparent:
many records must be posted on the in-
ternet to allow easy public accessibility.
Requiring a website is an interesting de-
velopment and is an obvious next step
in regulatory communication.
On April 17, 2015, the Environmental
Protection Agency (EPA) published the
final version of the federal CCR rule
on the storage and disposal of CCRs
generated by electric utilities. The CCR
rule is expected to affect more than
1,000 active CCR management units
throughout the U.S, particularly the
owners and operators of CCR landfills
and surface impoundments. The new
rule includes provisions addressing the
potential for catastrophic failure of CCR
containments, groundwater monitoring,
operational requirements, recordkeeping
and reporting, as well as closure
procedures for inactive or failing facilities.
Under the rule, there are numerous
requirements that must be performed
by a professional engineer, and others
by a qualified individual. The rule will
require installation of groundwater
monitoring wells, and a groundwater
monitoring program for taking
samples and assessing that data. In
addition to thorough recordkeeping
and notification requirements, owners
and operators of CCR sites are now
required to maintain a public website
hosting all compliance information,
including monitoring reports. The rule
also outlines timeframes and procedures
for site closure, and also details closure
consequences for sites failing to meet
these criteria. The first provisions of
this rule are expected to take effect on
October 19, 2015.
As part of these provisions, all owners
and operators of over 1,000 identified
active landfills and surface impound-
ments, currently receiving CCRs are
now required to establish and maintain
a website of CCR facility operation-
al compliance data called “CCR Rule
Compliance Data and Information.”
The website must be made publically
available, and host items identified in
the CCR rule are required to be publi-
cally accessible. Some of the items that
must be included are annual ground-
water monitoring results, corrective ac-
tion reports, fugitive dust control plans,
structural stability assessments, emer-
gency action plans, and closure com-
pletion notifications. As information is
uploaded to the site, notifications must
be sent to the state and local tribal au-
thorities.
The requirement for a website stems
from another unusual aspect of the CCR
rule: the rule does not require permits,
does not require states to adopt or
implement these requirements, and EPA
cannot enforce these requirements. EPA
has promulgated a rule that relieves itself
of the burden of assessing compliance.
Commenters on the draft rule fell on
both sides of the argument as to whether
or not civilian enforcement would be
effective. Some were encouraged by
the opportunity to enforce the rule
themselves since “…citizens have shown
no reluctance to challenge companies
that they believe are not responsibly
following environmental regulations.”
Others felt “environmental justice
Kicking Ash
and Taking Names
BY APRIL ESCAMILLA, BURNS & MCDONNELL, AND
ROBYNN ANDRACSEK, P.E., BURNS & MCDONNELL
AND CONTRIBUTING EDITOR

12 www.power-eng.com
RENEWABLE POWER
T
he utility-scale solar en-
ergy industry is feeling
its oats. The cost of gen-
erating electricity from
solar power has plum-
meted in recent years, and experts say
it will continue to drop. Utility-scale
solar is on par with, if not cheaper
than, power produced with fossil fuel
in many markets in the U.S., and there
are more than 27 GW of solar projects
either under construction or in the
planning stages.
Yet, there are a few clouds darken-
ing the utility-scale solar market. The
darkest being the possible sun setting
of federal investment tax credits (ITC)
at the end of 2016.
Solar has about 1 percent of the
power generation market in the U.S.,
but the industry is scoring some his-
toric firsts. Georgetown, Texas, about
50 miles north of Austin, recently an-
nounced that it will use solar and wind
power to become one of a handful of
U.S. cities running on 100 percent re-
newable energy.
The solar power will come from a
150 MW project in West Texas, accord-
ing to John Lamontagne, senior direc-
tor of corporate communications at
SunEdison. What’s interesting about
the announcement is why the city
chose SunEdison: price.
“They did it because we were the
lowest cost option for local ratepayers,”
Lamontagne says. “In other words,
solar energy (along with wind power)
were the cheapest ways to power that
town.”
PROJECT PROFILE
There are two main ways to gener-
ate solar power: photovoltaic cells or
concentrated solar power (CSP). CSP
uses mirrors to focus solar energy to
create heat, which can then power a
traditional steam turbine. Photovoltaic
cells use an electronic process to con-
vert sunlight into electricity.
The Ivanpah Solar Electric Generat-
ing System uses solar thermal technol-
ogy to produce energy. Unlike tradi-
tional solar farms, more than 300,000
computer-controlled mirrors track the
sun and reflect it towards boilers that
sit atop immense towers. Steam is cre-
ated when the concentrated light hits
the boilers. The steam is piped to a tur-
bine where it creates electricity.
Ivanpah, which has been live since
January 1, 2014, has three units with
a total generating capacity of 377 MW.
Units 1 and 3 provide power for Pa-
cific Gas & Electric while unit 2 sends
electricity to Southern California Edi-
son. The plant has a 30-year license to
operate on public land in California’s
Mojave Desert, 45 minutes southwest
of Las Vegas. About 65 full-time op-
erations and maintenance employees
work at the plant.
Ivanpah, a partnership between
BrightSource Energy, Google and
Large-Scale
Solar on the RiseBY ROBERT SPRINGER
NRG called Solar Partners, was built
by Bechtel. NRG Energy Services han-
dles the plant’s operations and main-
tenance.
The plant reaches full load during
sunny days, says Mitchell Samuelian,
vice president of operations and main-
tenance for NRG Renew and the former
general manager of Ivanpah. “On sun-
ny days we’ve made over 103 percent
of our estimated energy that we were
supposed to reach in the year,” he says.

13www.power-eng.com
The challenge is how to produce the
most electricity during partly cloudy
weather. The goal, explains David
Knox, senior director, wholesale and
new business communications at
NRG, is to “collect as much solar en-
ergy as you can to start it up as quickly
as you can, and then to continue that
throughout the day, whether it be high
noon or early evening and optimizing
that throughout the entire day.”
This is technically very challenging
to do, according to Samuelian, “Be-
cause you’ve got clouds moving in and
out and you’ve got a steam plant with
thermal inertia and the parts and piec-
es move around,” he says.
In the early morning, virtually all
of the mirrors are aimed at the tower,
but as the day goes on some go into a
standby position so the tower doesn’t
overheat. The process is regulated by
infrared cameras, Samuelian says.
“They monitor the boilers surface with
infrared cameras, and they balance
turbine load with the amount of solar
they’re putting in and with how much
sunlight’s in the sky,” he says.
The boiler has three sections – super
heat, reheat and evaporator – and mul-
tiple mirrors heat a different section
of the boiler. Supercomputers balance
the energy on the three spots and give
aiming signals to each unit every 10 sec-
onds, according to Samuelian.
“I think that people don’t understand
The Ivanpah Solar Electric Generating System uses
mirrors to direct concentrated solar power at a
boiler,which produces steam to power a turbine and
produce clean electricity for Northern and Southern
California.Photo Courtesy:Ivanpah Solar Electric
Generating System
Author
Robert Springer is an Oregon-based
freelance journalist covering the energy
industry. His work has been published in
several publications, including Renew-
ableEnergyWorld.com and Power Engi-
neering magazine.

RENEWABLE POWER
the complexity associated with that. I
mean these are actually run by big su-
percomputers that control the system,”
says Samuelian.
The plant uses recycled water, and
is using much less than originally
thought, at about 40 percent of the 100
acre feet allotment for all three units, ac-
cording to Samuelian. Using air-cooled
condensers helps, as does having “a
closed loop cooling system that ejects
the heat to the air rather than evaporat-
ing water. There’s a golf course next to
us out in the desert, and I think we use
the amount of water equal to two holes
on the golf course,” Samuelian says.
Another challenge is the sheer size of
the plant. A coal-fired plant of similar
size would have a much smaller foot-
print, Samuelian says. Ivanpah’s three
units cover about 3,000 acres and is
about five miles end to end. “So if I’ve
got someone working in the solar field
on one end of the plant and I need them
to go look at something else on the oth-
er end of the plant, there’s restrictions
on what speed you can drive onsite, for
wildlife considerations, and creating
dust, and so, the speed limits like 10
miles an hour,” says Samuelian. It takes
about half an hour to go from one end
of the plant to the other.
FOLLOWING THE
PHOTONS: SOLAR IS MORE
THAN PANELS
Solar panels get the lion’s share of
the publicity, but they’d just be large,
shiny mirrors without the ability to
take the electricity the solar panels pro-
duce from the panel to the grid. ABB, a
global provider of power and automa-
tion technologies, manufactures and
installs the equipment that allows util-
ities to get solar energy onto the grid.
ABB’s products take over once the
solar panels have converted the ener-
gy from photons into DC power, says
Bob Stojanovic, ABB’s director of solar
power for North America. “What ABB
makes is everything from the connec-
tors that connect the cabling to the de-
vices,” he says.
Groups of solar panels (or “strings”)
run in a series and in parallel until they
get the maximum voltage they’re de-
signed for, and the electricity is taken
to a combiner box, which is a group of
fuses and switches that take the input
from the strings and combine it into a
single output, according to Stojanovic.
“And that typically runs back to another
larger combiner box, which is typically
a bunch of breakers or large fuses that
take the rest of these strings and com-
bine it into one big DC input into an
inverter,” he says.
The DC power needs to be converted
to AC to reduce losses and because that’s
what the North American grid supports.
Stojanovic says they typically get
somewhere around 300 to 690 volts
of AC out of the inverter, and “then it
goes through what’s called an inverter
step-up transformer” or padmount
transformer, he says. The transformer
typically boosts the voltage up to 34.5
KV.
Although there are small losses
during the conversion process, the fi-
nal boost to 34.5 KV will decrease the
loss as the power is sent to the substa-
tion, according to Stojanovic. “Inside
the substation you’ll typically string,
depending on the plant design, some-
where between, five to eight converters
together on the same circuit, and you’ll
bring it back to a main breaker, a feeder
breaker which will then feed it into the
main power transformer,” he says.
ABB manufactures turnkey substa-
tions and almost all of the equipment
that’s in the substations, Stojanovic
says, “Everything from the reclosers to
the tank breakers to the power trans-
formers, the current transformers, and
the instrument transformers where
you measure power and voltage.”
Stojanovic says that ABB has no
ABB provides concentrated solar power
and thermal automation solutions for
solar farms around the world,including
this customized application with eSolar’s
Sierra SunTower facility in Southern
California.Photo Courtesy:ABB

exist? No, definitely not. It has become
very competitive to the point where I
think it would certainly cause a consid-
erable slowdown in the industry, but
I’m confident that the industry can ab-
sorb it if it’s forced to,” he says. “It will
certainly spur a high level of consolida-
tion in the industry and only the very
strong and very efficient will survive
the expiration of the ITC. “
David Feldman, senior financial an-
alyst at the National Renewable Ener-
gy Laboratory, notes that the personal
homeowner credit completely goes
away, so the distributed market could
be harder hit than the utility-scale one.
He also thinks it’s time for the ITC to
go away entirely, albeit gradually. “The
best thing that I think that could hap-
pen is that they just agree to somehow
put some sort of orderly ramp-down in
place rather than just a hard cliff; but I
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desire to enter the solar panel market,
although the company looked into
it a few years ago, as they realized it
was not a core competency. “What we
manufacture is power and automation
equipment. That’s really where we can
add value,” he says.
WHAT HAPPENS IN 2017?
There are a myriad of predictions for
what would happen to the U.S. solar
industry if the federal investment tax
credit were to decrease from the cur-
rent 30 percent to 10 percent in 2017.
The predictions range from an extreme
disruption of the industry to a 12 to 18
month hiccup in the industry’s rapid
growth of the past few years.
“I think right now people are pro-
ceeding with cautious optimism,” says
Katherine Gensler, director of gov-
ernment affairs for the Solar Energy
Industries Association (SEIA). “This
is in contrast to say the last five or six
years, where there was sort of a boom-
ing industry and a growing industry.”
Gensler adds that the eight year ITC
extension that the industry received in
2008 allowed the industry to grow and
especially helped larger utility-scale
projects that had long lead times.
Charles Pimentel, Solar Frontier’s
chief operating officer, is not optimis-
tic that congress will extend the ITC in
its current form, although he is “con-
fident that congress will provide some
kind of interim solution, whether it be
a complete extension, or whether it be
some kind of safe harbor, or some kind
of grandfathering in of projects com-
pleted by the end of 2016,” he says.
He doesn’t foresee long term damage
to the industry if the ITC is allowed
to expire. “Will the industry cease to

RENEWABLE POWER
commission to leave things as they are,
while Pacific Gas & Electric and South-
ern California Edison want payments
lowered to new net metered installa-
tions.
FUTURE OF SOLAR IN N.A.
While experts agree that solar has a
place at or near the head of the table
of renewable energy options for North
America, the industry has some sub-
stantive challenges in addition to the
possible expiration of the ITC at the
end of 2016.
ABB’s Stojanovic is an “optimist”
when it comes to technological innova-
tions that will continue to drive down
equipment costs and increase efficien-
cies in the next few years. “They’ve ba-
sically proven everybody wrong over
the last five years by blowing away
whatever cost curves they thought they
think whoever’s in office, it’s going to
take congress as well as the president
to decide what the policy is going for-
ward. But all energy is policy, so it’s not
just solar,” he says.
NET METERING:
A DEBATE IN MANY STATES
Net metering, or the process of selling
excess electricity generated on-site back
to a utility at retail power rates, is an
issue that utilities and solar-using rate
payers are passionate about. The rate
at which customers are paid for energy
sold back to a utility impacts its bottom
line and the cost effectiveness of a roof-
top solar installation, experts say.
Pimentel says that while net meter-
ing does impact a utilities bottom line,
it won’t destroy their business model
as rooftop solar is such a tiny percent-
age of the energy generated in North
America.
“If a homeowner is typically paying
the utility $250 every month and all
of a sudden the utility is only getting
$15 a month, that impacts their reve-
nue,” he says. However, if a utility has 2
million customers and only 5,000 use
solar “it’s not going to destroy the utili-
ty. It will affect their revenue and their
economics, but it’s certainly not going
to destroy them,” he says.
It makes sense for customers to be
paid the retail rate, according to Feld-
man, as utilities don’t have to pay for
pay transmission charges, the facili-
ties are collocated and there are other
benefits which make distributed solar
worth a higher value price.
The solar industry itself is of two
minds about net metering. In Califor-
nia, the SEIA and the Alliance for Solar
Choice have asked the public utilities
Solar Frontier’s CIGS solar modules provide 82.5 MW of
the Catalina Solar Project’s 143 MW.The project is near
Bakersfield,California.Photo Courtesy:Solar Frontier

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plants are not being planned for post
2016 until the ITC debate is resolved.
“There’s a lot more uncertainty about
the near-term future, but then once we
get through the uncertainty, the indus-
try is strong and will continue to grow,”
she says.
had in line,” he says.
Solar’s biggest challenge going for-
ward is making energy that’s affordable
in the daytime also affordable at night,
Stojanovic said. “I don’t think cost for
solar is the issue anymore,” he says.
Interconnection continues to be an
issue, according to Feldman. Putting
the right amount of solar technology in
the right location at the right cost is a
challenge. He says that a utility indus-
try that has placed a high premium on
reliability (a good thing) might be act-
ing too conservatively when it comes
to solar. In addition to reliability, flexi-
bility and storage are important factors
for utilities to consider, Feldman says.
Samuelian thinks era of the me-
ga-solar projects is over, as the low
price of oil and natural gas is “really
kind of driving the energy market in
general,” he says. Knox sees the home
solar market as “an incredible growth
market,” he says. “We just really see a
huge potential for the home solar mar-
ket, not instead of but in addition to
the utility-scale market.”
Many different technologies – in-
cluding wind, storage, diesel genera-
tors and solar – could converge to help
create a self-sustaining micro grid,
Samuelian says.
The number of states that have ag-
gressive solar and renewables programs
has grown exponentially, Pimentel
says, with North Carolina being the
poster child for this group. “Two years
ago, nothing was going on in North
Carolina, and now North Carolina will
do gigawatts next year,” he says. Geor-
gia is also getting into solar in a big
way, according to Pimentel.
New markets will be important for
the industry, Feldman says, as states
start to satisfy their Renewable Port-
folio Standards (RPS). If Arizona, for
example, hits its RPS, utility-scale so-
lar might not make sense there as the
demand will have evaporated. On
the other hand, states like California
and Hawaii have very aggressive RPS’,
which could balance out the demand.
Solar is also competing against wind,
Feldman notes.
Gensler says that there is “still some
trajectory” left in the market through
2016, but large utility-scale solar

EMISSIONS CONTROL
JEA’s Northside Generating Station includes two Amec Fos-
ter Wheeler CFB boilers,each producing 831,000 ACFM of
flue gas.Each boiler uses a single SDA followed by a pulse
jet fabric filter to treat the flue gas produced by the pet
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to 99 percent.The plant has been in operation since 2002.
Photo Courtesy:Amec Foster Wheeler
Circulating
Fluidized Bed
Scrubber vs.
Spray Dryer
AbsorberBY MATTHEW FISCHER AND GREG DARLING
Toxics Standards or MATS), Regional
Haze (RH), and SO2
, NOx, and partic-
ulates (Cross-State Air Pollution Rule
or CSAPR) have ratcheted up the pres-
sure on coal-fired generators to quickly
reduce a variety of pollutants. The EPA
estimates that CSAPR alone requires
more than 3,000 units at more than
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duce emissions that cross state lines and
contribute to ground-level ozone and
fine particle pollution. CSPAR Phase 1
compliance takes effect this year while
MATS and RH reduction are ongoing
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The debate over what limits will be
imposed has now shifted to how indi-
vidual units will comply with the pre-
scribed deadlines. There are as many
technical approaches to meeting new
emission limits as there are differences
in plant designs. Adding to the com-
plexity of any solution is the uncertain-
ty of future rules that will require fur-
ther reductions of an expanding range
of pollutants.
In the past, SO2
capture on a large
scale was the province of wet flue gas
desulfurization (WFGD) technology.
It has the advantage of a relatively low
operating cost and uses readily available
limestone as the reagent, which can be
recycled into a number of useful prod-
ucts to offset operating costs. However,
WFGD scrubbers do have disadvantag-
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systems require periodic discharge of
the scrubber liquor to maintain solids
M
any utilities are
under pressure to
add flue gas desul-
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coal-fired units in
response to more stringent air emis-
sions regulations. There are a number
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available that have an edge over wet flue
gas desulfurization systems. This article
sorts out the difference between state-
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scrubbers and the latest advanced spray
dryer absorber designs.
By Matthew Fischer and Greg Dar-
ling, Amec Foster Wheeler
The converging U.S. Environmental
Protection Agency (EPA) rules for re-
ducing mercury, metals, acid gases, and
organic compounds (Mercury and Air
Author
Matthew Fischer is Product Leader, Dry
FGD Systems, and Greg Darling is Prod-
uct Leader, CFBS Systems, for Amec Fos-
ter Wheeler North America Corporation
Global Power Group – Environmental
Systems.

1SDA Design Details
Source: Amec Foster Wheeler
The SDA uses hydrated lime to treat flue gas.The heat of the flue gas
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the dried products is directed to a fabric filter.
Solids Discharge
Hopper
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Distribution
Plate & Flow
Straightener
Flue Gas In
Reaction
Vessel
Two-Phase
Reaction
Process
Two Fluid
Nozzles
Flue Gas Out
19www.power-eng.com
The optimized two-fluid nozzle design ensures balanced atomizing air distribution in order to produce a
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Two-Fluid Nozzles Released 2
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Nozzle
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Atomizing Air
Shroud Air
Lance
Assembly
Two Fluid
Nozzle
Lime Slurry
Atomizing Air
Air
Reservoir
absorber (SDA), which sprays atom-
ized lime slurry droplets into the flue
gas. Acid gases are absorbed by the
atomized slurry droplets while simul-
taneously evaporating into a solid par-
ticulate. The flue gas and solid partic-
ulate are then directed to a fabric filter
where the solid materials are collected
from the flue gas. Amec Foster Wheeler
has installed 60 SDA units represent-
ing over 4,500 MW of plant capacity.
The second is the circulating fluidized
bed scrubber (CFBS, which circulates
boiler ash and lime between a scrubber
and fabric filter. Amec Foster Wheeler
has install 78 CFB scrubber units rep-
resenting over 7,000 MW of capacity in
the power and industrial industries.
Spray dryer absorber
SDA technology operates using ab-
sorption as the predominant collec-
tion mechanism. In general, the acid
gas dissolves into the alkaline slurry
droplets and then reacts with the alka-
line material to form a filterable solid.
Intimate contact between the alkaline
sorbent (hydrated lime) and flue gases
make the gas removal process effective.
and/or chlorides. This effluent requires
additional treatment which adds capital
and operating costs. Also the uncertain-
ty of future regulations, specifically the
Steam Electric Power Generating Efflu-
ent Limitation Guidelines (ELG), may
require additional discharge treatment.
WFGD is also limited in its ability to
capture mercury and SO3
. Some plants
have reported increased mercury re-
moval as a desirable, but expensive
co-benefit when a selective catalytic re-
duction (SCR) system for NOx removal
was installed upstream of the WFGD
scrubber. Other plants have also add-
ed injection of one or more proprietary
reagents into the furnace, such as dry
sorbent injection (DSI), as a means to
increase the mercury removal co-ben-
efit. Stacking technologies is not a cost
effective long-term strategy to reduce
pollutants—it’s unnecessarily expen-
sive and reduces the overall reliability of
the entire unit. A more holistic solution
is preferred.
TECHNOLOGY
COMPARISON
Interest in dry or semi-
dry FGD scrubbers is in-
creasing due to its ability
to capture mercury, acid
gases, dioxins, and fu-
rans, in addition to SO2
and particulates. These
multi-pollutant technol-
ogies also have added
benefits: no liquid dis-
charge and significantly
reduced water consump-
tion, which is increas-
ingly important to pow-
er plants that are under
pressure to reduce water
consumption.
Two multi-pollutant
technologies dominate
the utility sector. The
fundamental difference
between the two tech-
nologies is the manner in which the re-
agent is mixed with the incoming flue
gas to remove the desired pollutants.
The first technology is the spray dryer

Source: FWEC
The principal operating steps is recycling a solids/hydrated lime and water mixture in the flue gas flow
to capture pollutants, cool the gas, and then capture solids in a fabric filter. Other reactive absorbents
like activated carbon can be added to target specific pollutants.
CFBS Design Details 3
Inlet Flue Gas
and Ash
CFB Scrubber
Fabric Filter
Air
Air
Water
Hydrated
Lime
Solid By-
Product
Reactor Ash Drain
EMISSIONS CONTROL
frequency (1–3 weeks continuous
operation), reduced cost of operation
(20-25 percent less compressed air
consumption), and longer life with
its new tungsten carbide inserts. In
addition no special tools are required
for routine maintenance.
The SDA design also provides
additional operating flexibility for
the entire plant. For example, any
two-fluid nozzle can be removed
for maintenance without decreasing
boiler load. Emissions performance is
maintained even when multiple two-
fluid nozzles are taken out of service.
The SDA is also capable of high unit
turndown, down to 25 percent of rated
flue gas flow without recirculation
of the flue gases while maintaining
emission requirements.
The design of the unit also provides
for fast load response enabling unit
cycling or load following. An added
advantage is low absorber pressure
drop that keeps the parasitic fan power
loss to a minimum.
The key to efficient performance is the
means used to atomize the lime slurry
into droplets within the gas stream. The
SDA offered by Amec Foster Wheeler uti-
lizes a two-fluid nozzle to atomize the
lime slurry. The fine spray provides in-
creased contact area in order for gas ab-
sorption to occur compared to the CFBS
(it’s easier to mix a gas with a liquid
than with a solid). Acid gases are then
absorbed onto the atomized droplets.
Evaporation of the slurry water in the
droplets occurs simultaneously with
acid gas absorption. The cooled flue
gas carries the dried reaction product
downstream to the fabric filter. This
dried reaction product can be recycled
to optimize lime use.
Industry experience with earlier
SDAs was they were expensive to
operate and maintain regardless of
the atomization mechanism used.
Amec Foster Wheeler has redesigned
its two-fluid nozzle to improve the
distribution and mixing of atomizing
air with lime slurry, which improves
mixing efficiency and decreases
operating and maintenance costs.
The optimized nozzle design delivers
even atomizing air distribution to
produce a consistent droplet size
while providing longer nozzle life. In
14 field applications, the optimized
nozzle has demonstrated low cleaning
The 420MW-rated coal-fired unit at Basin
Electric’s Dry Fork Station has operated
the world’s largest CFBS since it entered
service in June 2011. Since it began
operation,the CFBS has exceeded its
design performance reducing SO2 by 95
percent to 98 percent.Photo Courtesy:
Basin Electric Co-Op and Wyoming
Municipal Power Agency

21
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www.power-eng.com For info.http://powereng.hotims.com RS#8
Circulating fluidized bed scrubber
Boiler flue gas enters the CFBS (with or without
ash) at the bottom of the up-flow vessel, flowing
upward through a venturi section that accelerates the
gas flow rate, causing turbulent flow. The turbulator
wall surface of the vessel causes highly turbulent
mixing of the flue gas, solids, and water for 4 to 6
seconds to achieve a high capture efficiency of the
vapor phase acid gases and metals contained within
the flue gas. The gas and solids mixture then leaves
the top of the scrubber and the fabric filter removes
the solid material.
Recycled solids/hydrated lime and water mix with
the turbulent flowing gas moving vertically through
the vessel, which provides gas cooling, reactivation
of recycled ash, and capture of pollutants. The
CFBS process achieves a very high solids-to-gas
ratio, which dramatically improves the ability of
vapor phase pollutants to find adsorption sites on
the colliding solid particles. The water plays the
important role of cooling the gas to enhance the
adsorption of the vapor phase pollutants onto the
solid particles.
The gas and solids mixture exit at the top of the
scrubber and enter the fabric filter where solids
entrained in the flue gas are captured and recycled back

Source: FWEC
Flue gas enters vertically upward into the scrubber and through a set of venturis that accelerate the
gas flow.Wall turbulators increase flue gas and reagent mixing efficiency.Multiple venturis allow a single
scrubber to be scaled up to 600 MW in unit capacity.
Turbulent Mixing 4
Absorber
Bottom
Recycled Solids
Multiple Venturi Design
CFB
Scrubber
Dry Flue Gas
with Solids
Raw Flue
Gas & Ash
Hydrated Lime
Water
EMISSIONS CONTROL
scrubbing performance over a wider
range of fuel sulfur content. SDA sys-
tems are temperature limited because
fresh lime is introduced as slurry (lime
and water). In addition, due to water
being introduced independently and
purely for temperature control, the
CFBS can utilize lower quality water, as
it is not used for pebble lime hydration.
The CFBS has the ability to effective-
ly treat more flue gas volume than an
SDA. The multiple venturis present al-
low a single CFBS vessel to be scaled up
to almost twice that of the SDA vessel
option.
Turndown capability is built into
the SDA design, where a CFBS requires
a flue gas recirculation system in or-
der to achieve equivalent turndown.
An SDA utilizing the two-fluid nozzle
design can maintain required emis-
sion levels down to approximately 25
percent of MCR. In a CFBS at lower
loads additional recirculated flue gas
is required to maintain bed velocities
in order to maintain required emission
levels. If turndown during non-peak
power demands is a consideration the
additional parasitic load is an operat-
ing cost consideration for the CFBS.
The CFBS provides greater sor-
bent utilization compared to a once-
through SDA system as reagent recycle
is incorporated into the design. How-
ever, due to the difference in hydration
efficiency, a SDA equipped with recy-
cle offers greater overall sorbent utili-
zation compared to CFBS. In an SDA
the recycled solids are slurried within a
tank providing essentially 100 percent
hydration. In a CFBS water spray noz-
zles wet the dry recirculated solids as it
passes through the vessel. This hydra-
tion process is less efficient due to the
quantity of recycled solids and the lack
of sufficient wetting time.
All the other performance character-
istics are relatively equivalent including
net auxiliary power. The pressure drop
in the SDA (10 inches H2
O) is much
to the scrubber to capture additional
pollutants. A portion of the recycled
solids is removed from the fabric filter in
order to maintain the right quantity of
material in the circulating loop.
The effectiveness of the sorbent is
largely a function of residence time. A
CFBS can keep solids in the system from
20 to 30 minutes. This is a sufficient
period of time for the sorbent to react
with the acid gases. Two independent
control systems maintain the dry flue gas
at optimum temperature and at adequate
removal efficiency by controlling the
amount of water added and the amount
of fresh sorbent added separately.
As a result, unlike the SDA scrubber,
pollutant capture is not limited by inlet
flue gas temperature.
TECHNICAL COMPARISON
Table 1 summarizes the important
technical differences between the SDA
and CFBS options. Table 2 summariz-
es the performance differences. In gen-
eral, the CFBS is slightly better at SO2
control, with up to 98+% capture with
high amounts of sulfur in the fuel.
Plant turndown capability is equiva-
lent, when the CFBS is equipped with
flue gas recirculation.
In general, the CFBS offers slightly
greater SO2
removal flexibility when
compared to SDA. The amount of fresh
lime injection is not limited by flue gas
temperature thus allowing greater SO2

23www.power-eng.com
Performance characteristic SDA CFBS
Fuel sulfur content < 2.5% < 3.5%
SO2
removal % 95 – 97 % 95 – 98+ %
Capacity per vessel 40,000 – 1,000,000 acfm
75,000 – 1,800,000
acfm
Turndown capability,
% of MCR flue gas flow
25% without FGR 50% without FGR
Sorbent Calcium hydroxide slurry 25% with FGR
Sorbent Treatment Slaker
Dry calcium
hydroxide
Sorbent Utilization
(Molar Ca/S ratio)
1.4 – 1.5 (without recycle) 1.3 – 1.4
1.15 – 1.25 (with recycle)
Control flexibility Temperature limited
Temperature
independent
Water quality Medium Low
Capital cost Slightly lower Slightly higher
Footprint,includes
fabric filter
Large in power island,
small overall
Moderate in power
island,small overall
KeyTechnical Characteristics of SDA and CFBS 1
Notes:MCR = maximum continuous rating; FGR = flue gas recirculation;
acfm = actual cubic feet per minute
Parameter SDA CFBS
SO2
removal efficiency,% 95 98
Expected SO2
removal,% 97 98+
SO3
removal,% 95+ 95+
HCl/HF removal,% 99 99
Total PM Removal efficiency,% 99+ 99+
Mercury removal efficiency,% (with or without PAC) Equal Equal
Pressure drop,inches H2
O 10 16
Auxiliary power consumption Higher Lower
Total power consumption (including ID fan) Equal Equal
Availability,% 99 99
Water consumption Equal Equal
Noise Equal Equal
Key Performance Characteristics of SDA and CFBS 2
Notes:ID = induced draft; PAC = powdered activated carbon; PM = particulate matter
approximately equivalent. However,
depending on the unit capacity, pres-
sure drop may have a greater operating
cost impact compared to the additional
auxiliary power of an SDA.
Both technologies are simple, reli-
able, and robust. When maintenance
of the CFBS is required, the accumu-
lated solids can easily be removed
through the bottom of the scrubber.
Also, the water nozzles are low main-
tenance and can be replaced with the
unit in operation. SDA two-fluid noz-
zles may also be removed and main-
tained during plant operation without
loss of unit capacity.
NO ONE SIZE FITS
ALL TECHNOLOGY
In the past, dry scrubbing technol-
ogy was typically chosen over WFGD
technology for its much lower capital
cost and water usage, provided that the
boiler size was not too large and the
fuel sulfur content was not too high.
Today, CFBS technology has broken
through these limitations with single
unit designs up to 600 MW backed by
operating units coal-fired units of over
500 MW and on fuels with sulfur levels
above 4 percent by weight. SDA have
also been deployed on equal-sized
units but are less tolerant to fuel sulfur
content change.
The utility retrofit market has leaned
more toward the CFBS technology of late
due to the higher SO2
removal perfor-
mance. The limited turndown without
flue gas recirculation and use of hydrat-
ed lime is also viewed as a disadvantage.
However, the new generation of SDA
nozzles now available has significant-
ly reduced cleaning frequency, which
was a major criticism by early adopters.
With extended nozzle life and reduced
compressed air consumption, the perfor-
mance gap between the SDA and CFBS
has narrowed. Specific site and environ-
mental permit requirements will be the
determining factor.
less than the equivalent sized CFBS
(16 inches H2
O), which is proportional
to ID fan power consumed. However,
the auxiliary power used by the SDA,
principally for compressed (atomizing)
air, exceeds that required by the CFBS.
The net result is that the total auxilia-
ry power used by the either option is

A 6 MWe ORC installation with air-coled
condenser in Germany.Photo courtesy:Siemens
SMALL GAS TURBINES

25www.power-eng.com
Improving
the Flexibility
and Efficiency of
Gas Turbine-Based
Distributed Power
Plants
F
or the past 100 years
across most of the world,
consumers have re-
ceived their electricity
from large central power
plants, which provide energy to the en-
tire system from a single location via
a network of transmission lines. This
model, which relies heavily on fossil
fuels, is facing an increasing number of
challenges.
The major initial efforts to reduce
the environmental impact of power
generation centered on fuel switching
from coal to natural gas, with plans for
massive centralized coal-fired power
stations giving way to more efficient,
less polluting, natural gas-fired power
plants in the so-called “dash for gas,”
changing the power mix from predom-
inantly thermal coal-fired steam tur-
bine plant to a more even split between
coal and combined cycle gas turbines.
With increasing global efforts to re-
duce greenhouse gas emissions, there
is an increasing penetration of inter-
mittent and variable renewable energy.
BY MICHAEL WELCH AND ANDREW PYM
Both wind and solar generation out-
put vary significantly over the course
of hours to days, sometimes in a pre-
dictable fashion, but often imperfectly
forecast. This intermittency and vari-
ability of wind and solar power gener-
ation presents challenges for grid op-
erators to maintain stable and reliable
grid operation, especially in countries
where renewable power is given dis-
patch priority, requiring redundancy
and flexibility in fossil-fueled power
generation so that the system can re-
spond quickly to these fluctuations,
outages and grid support obligations.
Predominantly to date this has been
achieved by operating central power
plant so that they maintain their con-
nection to the grid but run at part-load
so that they can rapidly respond to
transients on the system network.
Without sufficient system flexibility,
system operators may need to curtail
power generation from wind and
solar sources. The centralized power
generation model has created a trend
over the past century towards ever

Renewables Impact onAvailable Power Generation
Over aWeek In Germany In 2013
1
Pumped Storage
Gas
70.000
60.000
50.000
40.000
30.000
20.000
10.000
0
MW
23.06.
(Sun.)
22.06.
(Sat.)
21.06.
(Fri.)
20.06.
(Th.)
19.06.
(Wed.)
18.06.
(Tue.)
17.06.
(Mon)
Hydro
Nuclear
Lignite Coal
Hard Coal
Wind
Solar
the ability to operate at low output lev-
els, while still maintaining high effi-
ciencies, low emissions and low power
plant maintenance downtimes. Dis-
tributed Generation is also enabler for
enhanced smart grid capabilities.
FLEXIBILITY OF A
MULTIPLE GAS TURBINE
SOLUTION
Conventional modern large-scale
Combined Cycle Gas Turbine power
plant (CCGT) are usually based on a
single gas turbine with a single steam
turbine (1+1 configuration), or two gas
turbines with a common steam turbine
(2+1 configuration). While this con-
figuration offers very high efficiencies
at full load, in excess of 60 percent to-
day, the efficiency falls as load reduc-
es. There is also a minimum emissions
compliance load, which limits the op-
erating range of the power plant.
With around 1/3 of the total station
power generated by the steam turbine,
it can take over 30 minutes to achieve
full station load. In addition, with
the gas turbine shut down for main-
tenance in a 1+1 configuration, the
complete station is offline, whereas in
a 2+1 configuration, an outage of one
gas turbine will reduce station power
generation to less than 50 percent of
its rated output. A solution based on
multiple gas turbines may offer much
greater flexibility, improved efficiency
across the power range and enhanced
operability compared to a convention-
al CCGT solution.
The Advantages of Modularity
Modularity can help enhance plant
flexibility and reliability. By having
multiple units, load can be shared
across them, and units switched on
and off to match the required load.
This enables the power plant to oper-
ate efficiently over a much wider load
range within the permitted emissions
limits than a conventional CCGT can
achieve. Future plant expansion is easy
increasing unit sizes, based on the
assumption that larger units and
bigger plant provided lower cost
power generation due to economies
of scale, with small increases in power
generation efficiency also contributing
to this. The accepted penalty was losses
in the transmission and distribution
networks, and the potential for
consumers to lose their power supply
in case of transmission or distribution
system outages. However, maximum
efficiency occurs at full-load, so
operating a large central plant at
part-load reduces the efficiency of
power generation considerably, and
the need for part-load operation may
impact on the operational range of
the power station due to the need to
comply with emissions legislation. In
addition, cycling of the units, ramping
up and down in load, can create the
need for more frequent maintenance
and power station outages. A large
utility-scale turbine undergoing major
maintenance can require around two
to three weeks outage for disassembly,
inspection, parts replacement and
reassembly. Cycling also reduces
part life and severely impacts plant
economic returns and in some cases,
overall viability.
Another issue facing centralized
power generation is water usage. In
manypartsoftheworld,waterisascarce
resource for which power generation
competes with agricultural, industrial
and domestic needs. In 2010, World
Bank estimates indicated 15 percent
of the world’s water withdrawals were
used for energy production, and with
electricity demand expected to grow 35
percent by 2035, water usage for power
generation will increase significantly,
especially in systems relying on the
centralized generation model.
Distributed Generation can help ad-
dress all the above issues. By building
smaller, more flexible power plants
closer to the actual load centers, net-
work operators can better compensate
for the intermittency of renewables,
reduce transmission system losses and
improve security of supply and reduce
capital expenditure on capacity expan-
sion/augmentation while the power
plant operators by using multiple units
can optimize the plant design to meet
the needs of the network operators
with fast ramp up and turn down and
SMALL GAS TURBINES

Typical Modular Outdoor
GasTurbine Generator
Set Installation
2
3Typical StartTimes for Open
Cycle GasTurbines
PowerOutput(%)
100
80
60
40
20
0
Trent
SGT-800
Minutes
1 2 3 4 5 6 7 8 9 10
27www.power-eng.com
second and 200 kW/second.
However, gas turbines can also ac-
cept step load applications while still
maintaining power generation with-
in the required frequency and voltage
limits. The maximum acceptable step
load depends on the gas turbine design
– a single shaft gas turbine can accept
a larger single load application than
a twin-shaft variant – but this ability
to step load enables the turbines to
reach full load much faster than by
employing a simple ramp rate for load-
ing. Figure 4 shows the comparison of
time taken for a twin-shaft 12MW gas
turbine to reach full load using the
maximum permissible load steps for
this particular gas turbine model – full
load can be achieved in half the time
by applying load in steps.
Single-shaft gas turbine designs
can accept greater step loads, varying
from 50 percent to 100 percent de-
pending on the model, rating and site
conditions. In the case of a 50MW sin-
gle-shaft gas turbine, it is possible to
load the unit from zero to full load in
two steps within 30 seconds.
Reducing Maintenance Outages
When scheduled maintenance is re-
quired and parts need to be replaced,
to achieve simply by adding one or
more units whenever required, either
at the same location or at a different
tactical point in the power network,
rather than having to build a new large
power plant and associated transmis-
sion system. By distributing capacity in
this way a ‘virtual generation’ benefit
is also achieved via loss offset in the
transmission network. The modular at-
tributes also enable plant to be moved
easily if market conditions change or
the plant is sold. This reduces opera-
tional and financial risk which is ben-
eficial for accessing finance at more
favorable terms. Small gas turbines
tend to come in pre-designed, pre-as-
sembled standardized packages which
have undergone significant levels of
factory testing and require only a sim-
ple concrete foundation. This reduces
the amount of planning, engineering,
site installation and construction work
required compared to a conventional
power plant, enabling the power plant
to be brought online faster, while still
maintaining a competitive first cost,
and reduces the risk of construction
delays and associated contract penal-
ties in addition to lost revenue. In ad-
dition, these packages can be supplied
with weather-proof acoustic enclo-
sures, eliminating the need for build-
ings. All the auxiliary systems required
for turbine operation – including the
control system - can be mounted ei-
ther within the enclosure, adjacent to
the enclosure or on the enclosure roof,
minimizing the number of intercon-
nections required.
Having multiple units also helps
maintain high power plant availabil-
ity and output. As mentioned earlier,
with a single gas turbine installation,
a maintenance outage means that the
entire power station has to be taken of-
fline. A power plant of similar output
but based on, say, 5 smaller gas tur-
bines can still generate 80 percent of
rated station output with one turbine
out of service, 60 percent with two
turbines out etc. Decentralized power
plant using this concept have been used
for many years
in the Oil & Gas
industry for on-
shore fields and
offshore platforms
with no possibili-
ty to connect to a
power grid, with
many Oil & Gas
operators choos-
ing the so-called
‘N+1’ configura-
tion so that there
is a spare unit to
ensure 100 per-
cent power output
is available even
with one gas tur-
bine out of ser-
vice.
Ramp Rate
The ability of a power plant to re-
spond rapidly to variable grid demands
is critical in today’s power environ-
ment with a high percentage of inter-
mittent renewable power generation.
Multiple small gas turbines allow the
full plant load to be achieved relatively
quickly from pushing the start button
as the units can ramp up in parallel.
The ramp rates of small gas tur-
bines typically range between 100 kW/
SMALL GAS TURBINES

A 7.7 MWTri-Fuel GasTurbine
Installed in a Cogeneration
Plant in the U.S.
5
Expected Ramp Rate and Step LoadAcceptance
for aTwin-Shaft 12-MW GasTurbine
4
PowerOutput(MW)
14
12
10
8
6
4
2
0
Seconds
Ramp
Step
0 5 10 15 20 25 30 35 40 45 50 55 60
reducing the maintenance require-
ments still further.
FUEL FLEXIBILITY
While Utility-scale gas turbines are
designed primarily for operation on
pipeline quality natural gas with a pre-
mium liquid fuel such as diesel as an
alternative or back-up fuel, the major-
ity of smaller gas turbine models are
able to operate on a much wider range
of gaseous and liquid fuels.
Low emissions combustion systems
have also been developed that will
operate on non-standard gas fuels,
including those with variable compo-
sitions. This is a potentially important
feature for decentralized power plant
as it enables the power plant to oper-
ate on a locally available fuel, which,
as some of these are classified as waste
gases, may also be more economical
than utilizing pipeline quality nat-
ural gas. Examples of such potential
gas fuels are landfill gas, digester gas,
high hydrogen content gases such as
refinery gas or syngas, ethane and pro-
pane. It is potentially possible to use
two completely different gas fuels and
switch between these fuels as neces-
sary, determined by fuel availability or
pricing.
Most gas turbines are available in
dual fuel configuration, able to oper-
ate on either gas fuel or liquid fuel. The
the large utility scale gas turbines re-
quire considerable downtime as the
unit has to be disassembled on site,
parts changed and then the unit reas-
sembled. The smaller gas turbines are
generally of Light Industrial or Aerod-
erivative designs which, while many
variants have the capability for on-
site maintenance as well, are primar-
ily designed for off-site maintenance
employing gas generator and turbine
module exchange programs. This re-
duces the turbine outage times for ma-
jor inspections from several weeks per
unit to between one day and five days
depending on the gas turbine model
and the type of maintenance interven-
tion required. Meanwhile in a power
plant based on multiple units, the re-
maining units are still available to gen-
erate power, enabling the power sta-
tion to stay online generating revenue,
with only a relatively small percentage
of total plant output unavailable.
Routine maintenance require-
ments during plant operation are also
low, with no requirement for highly
skilled maintenance personnel to be
permanently based on site and low
consumption of consumables such as
lubricating oil. The various gas
turbine OEMs are all working
on further developments to
improve system reliability and
remote monitoring systems to
enable unmanned operation
for prolonged periods of time.
As has been well-document-
ed elsewhere, the output of a
gas turbine is dependent on
ambient temperature: as ambi-
ent air temperature rises, a gas
turbine’s power output reduc-
es. Conversely this means that
if you design a power plant
to give a specific output at the maxi-
mum ambient temperature foreseen,
on cooler days more power is available
for dispatch. If there are distribution or
transmission system constraints that
limit the amount of power that can be
exported, then on cooler days, while
still producing maximum station out-
put, the gas turbines will operate at
part-load. Most GT OEMs calculate
the time between overhaul (TBO) for
the various different gas turbine mod-
els based on an Equivalent Operat-
ing Hours (EOH) formula – part-load
operation can help extend the TBO
SMALL GAS TURBINES

6Efficiency vs.Load Comparison
Efficiency versus load comparison for a 50-MW gas turbine (light blue line)
and 4 x 12.5-MW gas turbines (dark blue line) in open cycle at 40oC
ambient temperature.
4 x 12.5-MW gas turbines
PowerOutput(%)
40
30
20
10
0
Power Plant Output (MW)
0 10 20 30 40
50-MW gas turbine
Efficiencies 7
Typical gas turbine nominal efficiencies (vertical axis) by power output (horizontal axis)
with complex cycle designs indicated by circles.
50
45
40
35
30
25
20
15
10
5
0
Seconds
0 20 40 60 80 100 120
29www.power-eng.com
environmentally friendly manner for
base load, load following and peak-
ing service. Figure 6 compares the net
plant efficiency of a single 50MW class
aero-derivative gas turbine in open
cycle with four open cycle 12.5 MW
class gas turbines with performance
data calculated for an ambient air tem-
perature of 40° C. While at high loads
the single unit is more efficient, once
the power plant output drops below
50% of rated plant output, the multi-
ple unit solution has a higher efficien-
cy as units can be turned on and off
to maximize efficiency. The multiple
unit solution also offers a wider power
plant operating range from a combus-
tion emissions perspective. Most gas
turbine models guarantee nitrous ox-
ide (NOx) and carbon monoxide (CO)
from 50% of rated load to 100% of
rated load, as required by most global
legislation, although some units offer
these guarantees down to 30% or 40%
load. Therefore a single unit solution at
low loads will start to exceed the per-
mitted emissions. A multiple unit solu-
tion though enables the power plant
to have a greater turn-down capability
Smaller open
cycle (simple cy-
cle) gas turbines
have been used
for peaking ap-
plications for
many years be-
cause they can be
started quickly
and ramped up
and down rap-
idly to meet the
grid demands. In
open cycle, a gas
turbine is rela-
tively inefficient
with efficiencies
varying from
around 28% for a small industrial gas
turbine to just over 40 percent for the
larger aero-derivative gas turbines. In
peaking applications, this is perhaps
not so much of an issue as the price
of electricity is very high during the
periods of gas turbine operation, but
with increasing demand for flexible
power generation across the whole
day, a power plant today needs to be
able to operate efficiently and in an
turbines can operate on 100 percent
gas fuel or 100 percent liquid fuel, with
rapid automatic changeover between
the fuels with no requirement to tem-
porarily reduce load to undertake the
fuel change. The liquid fuels that may
be considered are typically #2 diesel,
kerosene, LPG and naphtha, although
there are gas turbine models available
that can utilize Light, Intermediate
and Heavy Fuel Oils, Residual Oils,
Bio-Oils and even Heavy Crude Oils.
On some gas turbines it is possible to
simultaneously operate on both gas
and liquid fuels – commonly referred
to as bifueling or mixed fuel operation
- using one fuel type to compensate for
shortage of another.
There are examples of tri-fuel gas
turbine installations, with units capa-
ble of operating on a gas fuel and two
different liquid fuels, or a liquid fuel
and two different gas fuels. Figure 5 is a
gas turbine installed in a cogeneration
plant at a university in the U.S. and
configured to operate on either pipe-
line quality natural gas or a processed
landfill gas, with diesel as a back-up
fuel in case of loss of gas supplies, while
still meeting strict emissions limits.
Improving Part-Load Efficiency
and Emissions Performance
SMALL GAS TURBINES

8EfficiencyVariations
NetPlantEfficiency(%)
41
40
39
38
37
36
35
34
33
32
31
33 66 100
Comparison of variation of efficiency with load based on a 25-MW power
plant using multiple small turbines and ORC or 42 bar, 400oC steam to
create a combined cycle plant.
ORC
Steam Cycle
temperature heat recovery steam gen-
erators (HRSGs) and steam turbine sys-
tems required to achieve this efficien-
cy level adds considerable cost. Lower
cost solutions using low pressure steam
systems can be employed, but this re-
duces the plant efficiency. In addition,
for decentralized plant located close to
load demand, the availability of water
may be an issue, or the operation and
maintenance level required by classical
steam solution cannot be easily accom-
modated, so an
alternative tech-
nology to generate
electricity from
the wasted energy
in the gas turbine
exhaust needs to
be considered.
Organic Ran-
kine Cycle (ORC)
Technology
The Rankine Cy-
cle is a thermody-
namic cycle which
converts heat into
work. For power
generation, by ap-
plying heat exter-
nally to a closed
loop, the working fluid is heated till
it becomes a vapor, expands across
a turbine to drive a generator and is
then cooled and condensed ready to
commence the cycle again. Water is
normally the working fluid used, and
the water (steam)-based Rankine Cycle
provides approximately 85 percent of
worldwide power generation.
A utility scale gas turbine tends to
have a high exhaust gas temperature,
typically between 530°C
(990°F) and 640°C (1180°F), as the
designs are optimized for combined
cycle applications with multi-pressure
level multi-pass boilers producing high
pressure, superheated steam (up to 160
bar and 600°C) for inlet to steam tur-
bines with reheat between different
while still complying with applicable
emissions legislation. In the example
in Figure 6, and assuming 50 percent
turndown limit, the power plant will
still meet emissions requirements
down to 12.5 percent of rated pow-
er plant output. However, for a truly
flexible power plant, the efficiency of
the gas turbines needs to be as high as
possible as well as providing as wide an
operating range for the power plant as
possible. While there are complex cycle
gas turbines on the market with recu-
perators and intercooling to improve
efficiency, the simplest, most effective
and most proven way to improve effi-
ciency is to use a combined cycle con-
figuration with energy recovered from
the exhaust of the gas turbine to gen-
erate additional power. Water (steam)
is the obvious choice as a working flu-
id to generate additional power via a
steam turbine, just as in a conventional
large-scale CCGT. However, smaller
gas turbines are not optimised for com-
bined cycle applications, having rela-
tively low exhaust mass flows and ex-
haust gas temperatures, and although
combined cycle efficiencies in excess
of 55 percent can be achieved, the
complexity of the high pressure, high
pressure levels within the steam tur-
bine. This is how a modern CCGT
achieves the high full load efficiencies
quoted, and produces electricity at
competitive prices through economies
of scale.
Smaller gas turbines have lower
exhaust gas temperatures, typically
between 460°C (870°F) and 550°C
(1025°F) as they are optimized for
maximum open cycle efficiency. This
reduces both the volume and tem-
perature of high pressure superheated
steam that can be produced, reducing
cycle efficiency. It is also not cost-effec-
tive to use the same Waste Heat Recov-
ery Unit and Steam
Turbine technology as developed to
go with a 300 MW gas turbine on a 10
MW gas turbine.
Therefore if a power plant is to be
based on multiple small units, effi-
ciency must be sacrificed to ensure
cost-effectiveness, so lower pressure
non-reheat steam systems are used, of-
ten with much simpler Once Through
Steam Generators (OTSGs) that re-
spond much more rapidly to changes
in steam demand. However, at low
pressures, there is a large enthalpy drop
experienced when water is the working
fluid, and a degree of superheat is re-
quired to avoid the risk of condensa-
tion, and associated erosion, inside the
steam turbine.
By changing the working fluid, a low
enthalpy drop can be achieved, the
need for superheating eliminated, as
condensation within the turbine can
be avoided, and the same efficiency
achieved at a lower working pressure.
Improved efficiencies at part-load are
also attainable using ORC turbogene-
rators compared to conventional steam
turbines.
Organic Rankine Cycles for small
gas turbines tend to use a high molecu-
lar weight hydrocarbon (organic) fluid
such as cyclopentane, or silicone oil, as
the working fluid for the turbine. This
SMALL GAS TURBINES

10Efficiency vs.Load Comparison
Efficiency versus load comparison for a 50-MW class gas turbine and 4 x 12.5 MW class gas turbines in open
cycle, with 4 x 12.5 MW class gas turbines with ORC at 40oC ambient temperature.
4 x 12.5-MW gas turbines with ORC
Efficiency(%)
50
40
30
20
10
0
MW
0 10 20 30 40 50
31www.power-eng.com
turbines are not
optimised for
combined cycle
applications, gen-
erally having low-
er exhaust tem-
peratures than
the utility scale
gas turbines, and
so they have re-
duced high pres-
sure steam raising
capabilities. How-
ever, the lower
exhaust tempera-
tures at both full
and part-load en-
able ORC technol-
ogy to be readily
employed to im-
prove overall plant efficiency while still
enabling multiple units to be installed
to maintain the overall power station
flexibility and operability. This config-
uration also has the additional advan-
tage of being able to be ‘water free’ as
air cooling can be used throughout the
installation.
Returning to our power plant capa-
ble of producing 40 MW at 40°C re-
ferred to in Figure 6, the addition of an
ORC turbogenerator to the smaller gas
allows high efficiency, larger diameter
turbines to be utilized, operating at
lower speeds, typically 3000rpm, with
low mechanical stress – unlike small
steam turbines which operate at speeds
up to around 10000rpm. The combina-
tion of working fluid and turbine speed
leads to much reduced maintenance re-
quirements, as well as eliminating the
need for water in the process.
ORC systems can use either directly
or indirectly heat the working fluid. In
both cases the Waste Heat Recovery
Unit (WHRU) installed in the gas tur-
bine exhaust system is a simple once
through design, but in the indirectly
heated system, heat is transferred from
the gas turbine exhaust to the ORC
working fluid via a secondary closed
loop using a thermal oil. Directly heat-
ed systems offer better efficiency of the
ORC cycle (see Figure 10 below) and
reduce the initial capital cost, while an
indirectly heated system allows for en-
ergy to be recovered from higher tem-
perature heat sources than a directly
heated system.
Combining Gas Turbines + ORC
to Maximize Performance
As mentioned earlier, smaller gas
turbines has quite a considerable im-
pact, as can be seen in Figure 12.
Firstly, it can be seen that the ORC
system adds about 25% additional
power output for the multiple small
units for no additional fuel input. Sec-
ondly, this additional power improves
the plant efficiency so that at full load
the overall net plant efficiency is in
excess of 40%, even on a hot day. This
efficiency improvement makes a nomi-
nal 50MW plant based on multiple gas
turbines more efficient and more flexi-
ble than a plant based on a single open
cycle gas turbine across the whole load
range, and with the ability to achieve
load turn-down to around 10 percent
of rated station power output while
still maintaining an acceptable com-
bustion emissions profile.
Multiple gas turbines can be con-
nected to a single ORC turbogenerator,
providing the maximum output rating
of the ORC turbogenerator is not ex-
ceeded. This helps reduce the cost/kW
of a power plant based on multiple gas
turbines as the cost of the ORC system
is spread across multiple units. In addi-
tion, thanks to ORC working fluid pe-
culiarities, the plant flexibility and ef-
ficiency at part load is not reduced. The
ORC unit can be operated at between
SMALL GAS TURBINES
9Comparison of ORC System
Efficiency for a Direct Heated and
Indirect Heated System
Efficiency(%)
25
20
15
10
5
0
10 30 50
Direct – 2 GTs
Oil – 2 GTs
Ambient Temperature (oC)

2015 09 Power Engineering

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